System and method for determining drilling parameters based on hydraulic pressure associated with a directional drilling system

ABSTRACT

A system and method for determining drilling parameters based on hydraulic pressure associated with a directional drilling system are disclosed. A drilling parameter associated with a directional drilling system may be determined by measuring hydraulic pressure associated with the directional drilling system during drilling of a wellbore, detecting a change in the hydraulic pressure, and determining a drilling parameter based on the detected change in hydraulic pressure.

FIELD OF THE DISCLOSURE

The present disclosure is related to downhole drilling tools including,but not limited to, drill bits, sleeves, reamers and bottom-holeassemblies, and more particularly to a system and method for determiningdrilling parameters based on hydraulic pressure associated with adirectional drilling system.

BACKGROUND OF THE DISCLOSURE

Various types of drilling systems including rotary drill bits, reamers,stabilizers and other downhole drilling tools may be used to form aborehole in the earth. Such wellbores are often formed using a rotarydrill bit attached to the end of a generally hollow, tubular drillstring extending from a well head. Rotation of a rotary drill bitprogressively cuts away adjacent portions of a downhole formation usingcutting elements and cutting structures disposed on exterior portions ofthe rotary drill bit. Examples of such rotary drill bits include, butare not limited to, fixed cutter drill bits, drag bits, PDC drill bits,matrix drill bits, roller cone drill bits, rotary cone drill bits androck bits used in drilling oil and gas wells. Cutting action associatedwith such drill bits generally uses weight on bit (WOB) and rotation ofassociated cutting elements into adjacent portions of a downholeformation to push the bit into the formation to cause cutting anddrilling. Drilling fluid may also be provided to perform severalfunctions including washing away formation materials and other downholedebris from the bottom of a wellbore, cleaning associated cuttingelements and cutting structures and carrying formation cuttings andother downhole debris upward to an associated well surface.

As drilling tools cut into a geological formation, the drilling toolsmay experience wear and lose efficacy. The amount of wear experienced bya drilling tool may be related to, among other things, the type offormation into which the drilling tool is cutting. For example, theharder the formation, the faster the drilling tool may wear. Theincreased wear may also cause undue strain on the drill string.

SUMMARY

In accordance with the present disclosure, the disadvantages andproblems associated with determining drilling parameters based onhydraulic pressure associated with a directional drilling system havebeen substantially reduced or eliminated. In one embodiment of thepresent disclosure, a method of determining a drilling parameterassociated with a directional drilling system includes measuringhydraulic pressure associated with a directional drilling system duringdrilling of a wellbore, detecting a change in the hydraulic pressure,and determining a drilling parameter based on the detected change inhydraulic pressure.

In another embodiment of the present disclosure, a directional drillingsystem includes a drilling tool including a drill bit and a steeringmechanism configured to direct the drill bit in a desired trajectoryusing hydraulic pressure. The directional drilling system also includesa hydraulic pressure sensor coupled to the steering mechanism andconfigured to measure the hydraulic pressure. Additionally, thedirectional drilling equipment is configured to receive the measuredhydraulic pressure from the hydraulic pressure sensor, detect a changein the measured hydraulic pressure, and determine a drilling parameterbased on the detected change in the measured hydraulic pressure.

In still another embodiment of the present disclosure, directionaldrilling equipment includes a processor, a computer readable memorycommunicatively coupled to the processor, and processing instructionsencoded in the computer readable memory. The processing instructions,when executed by the processor, are operable to perform operationsincluding: receiving a hydraulic pressure measurement associated with adirectional drilling system, detecting a change in the hydraulicpressure measurement, and determining a drilling parameter based on thedetected change in the hydraulic pressure measurement.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete and thorough understanding of the various embodimentsand advantages thereof may be acquired by referring to the followingdescription taken in conjunction with the accompanying drawings,wherein:

FIG. 1 is an illustration of an example directional drilling system fordrilling a wellbore, in accordance with some embodiments of the presentdisclosure;

FIG. 2A is a schematic illustration showing an isometric view withportions broken away of a rotary drill bit with six ( 6) degrees offreedom which may be used to describe motion of the rotary drill bit inthree dimensions in a bit coordinate system, in accordance with someembodiments of the present disclosure;

FIG. 2B is a schematic illustration showing forces applied to a rotarydrill bit while forming a substantially vertical wellbore, in accordancewith some embodiments of the present disclosure;

FIG. 3A is a schematic illustration showing a side force applied to arotary drill bit at an instant in time, in accordance with someembodiments of the present disclosure;

FIG. 3B is a schematic illustration showing a trajectory of adirectional wellbore and a rotary drill bit disposed in a tilt plane atan instant of time in a three dimensional Cartesian hole coordinatesystem, in accordance with some embodiments of the present disclosure;

FIG. 3C is a schematic illustration showing the rotary drill bit of FIG.3B at the same instant of time in a two dimensional Cartesian holecoordinate system, in accordance with some embodiments of the presentdisclosure;

FIG. 4 illustrates aspects of push-the-bit directional drilling systemsthat may be used in accordance with some embodiments of the presentdisclosure;

FIG. 5 illustrates aspects of point-the-bit directional drilling systemsthat may be used in accordance with some embodiments of the presentdisclosure;

FIG. 6 is a schematic illustration of a rotary drill bit showing changesin bit side forces with respect to changes in dog leg severity (DLS)during drilling of a directional wellbore, in accordance with someembodiments of the present disclosure;

FIG. 7 is an example illustration of a block diagram of directionaldrilling equipment and an associated measurement while drilling (MWD)system, in accordance with some embodiments of the present disclosure;and

FIG. 8 is a flow chart of an example method for determining drillingparameters based on hydraulic pressure, in accordance with someembodiments of the present disclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure and its advantages are bestunderstood by referring to FIGS. 1 through 8, where like numbers areused to indicate like and corresponding parts.

FIG. 1 is an illustration of an example directional drilling system 20for drilling a wellbore 60, in accordance with some embodiments of thepresent disclosure. Wellbore 60 may include a wide variety of profilesor trajectories such that wellbore 60 may be referred to as a“directional wellbore.” As described in further detail below withrespect to FIGS. 4-7, a directional wellbore may be formed by applyinghydraulic pressure to one or more drilling tools forming the wellbore inorder to steer the associated drill bit. The amount of hydraulicpressure may dictate the degree of change in the direction of thedrilling tool such that the hydraulic pressure may indicate thetrajectory of a directional wellbore. Additionally, the amount ofhydraulic pressure used for a certain trajectory may depend on thehardness of the formation being drilled. For example, a formation with arelatively high degree of hardness may require more pressure to achievea certain trajectory than another formation that has a lower degree ofhardness. Further, as cutting elements of a drilling tool wear, morepressure may be required to maintain a specific trajectory.Additionally, cyclic changes in the hydraulic pressure may indicateuneven force distribution along the drilling tool. Therefore, asdetailed below, drilling system 20 may be configured to measure theamount of hydraulic pressure being exerted to form a directionalwellbore in order to determine drilling parameters including, but notlimited to, cutting element wear, drilling characteristics, and/orformation changes. Such hydraulic pressure determinations may improvedrilling efficiency by, for example, helping project when to replace adrilling tool (e.g., a drill bit), improving the design of drillingtools, and making modifications to drilling based on formation changes.

Directional drilling system 20 may include land drilling rig 22.However, teachings of the present disclosure may be applied to wellboresusing drilling systems associated with offshore platforms,semi-submersible, drill ships and any other drilling system satisfactoryfor forming a wellbore extending through one or more downholeformations. The terms “downhole” and “uphole” may be used in thisapplication to describe the location of various components of a rotarydrill bit relative to portions of the rotary drill bit which engage thebottom or end of a wellbore to remove adjacent formation materials. Forexample an “uphole” component may be located closer to well head 24 ascompared to a “downhole” component, which may be located closer to thebottom or end of wellbore 60.

Drilling rig 22 and associated directional drilling equipment 50(similar to directional drilling equipment 700 configured to determinechanges in hydraulic pressure as described in detail with respect toFIG. 7) may be located proximate well head 24. Drilling rig 22 may alsoinclude rotary table 38, rotary drive motor 40 and other equipmentassociated with rotation of drill string 32 within wellbore 60. Annulus66 may be formed between the exterior of drill string 32 and the insidediameter of wellbore 60.

Directional drilling system 20 may include various downhole drillingtools and components associated with a measurement while drilling (MWD)system that provides logging data and other information from the bottomof wellbore 60 to directional drilling equipment (not expressly shown).The directional drilling equipment and its associated MWD system may beused to monitor and/or control drilling parameters associated withdirectional drilling system 20. In some embodiments, the MWD system maybe configured to measure the hydraulic pressure used to control thetrajectory of drill bit 100, as described in detail with respect toFIGS. 4-7.

Wellbore 60 may be a “directional wellbore” having multiple sections orsegments that extend at a desired angle or angles relative to vertical.Some of such angles may be greater than normal variations associatedwith straight holes. A directional wellbore sometimes may be describedas a wellbore deviated from vertical. A directional wellbore may includeany combination of “straight hole,” “slant hole” and “kick off”portions.

“Straight hole” wellbores or portions may refer to a wellbore orportions of a wellbore that extend at generally a constant anglerelative to vertical. Vertical wellbores and horizontal wellbores areexamples of straight holes. Most straight holes such as verticalwellbores and horizontal wellbores with any significant length may havesome variation from vertical or horizontal based in part oncharacteristics of associated drilling equipment used to form suchwellbores. A slant hole may have similar variations depending upon thelength and associated drilling equipment used to form the slant hole.

“Slant hole” wellbores or portions may refer to a straight hole formedat a substantially constant angle relative to vertical. The constantangle of a slant hole may typically be less than ninety degrees (90°)and greater than zero degrees (0°).

“Kick off” portions may refer to a portion or section of a wellboreforming a transition between the end point of a straight hole segmentand the first point where a desired dogleg severity or tilt rate isachieved. A kick off segment may be formed as a transition from avertical wellbore to an equilibrium wellbore with a constant curvatureor tilt rate. A kick off segment of a wellbore may have a variablecurvature and a variable rate of change in degrees from vertical(variable tilt rate).

Sections, segments and/or portions of a directional wellbore mayinclude, but are not limited to, a vertical section, a kick off section,a building section, a holding section (sometimes referred to as a“tangent section”) and/or a dropping section. Vertical sections may havesubstantially no change in degrees from vertical. Building sectionsgenerally have a positive, constant rate of change in degrees. Droppingsections generally have a negative, constant rate of change in degrees.Holding sections such as slant holes or tangent segments and horizontalsegments may extend at respective fixed angles relative to vertical andmay have substantially zero rate of change in degrees from vertical.

Transition sections formed between straight hole portions of a wellboremay include, but are not limited to, kick off sections, buildingsections and dropping sections. Such transition sections generally havea rate of change in degrees either greater than or less than zero. Therate of change in degrees may vary along the length of all or portionsof a transition section or may be substantially constant along thelength of all or portions of the transition section.

A building section having a relatively constant radius and a relativelyconstant change in degrees from vertical (e.g., constant tilt rate) maybe used to form a transition from vertical sections to a slant holesections or horizontal sections of a wellbore. A dropping section mayhave a relatively constant radius and a relatively constant change indegrees from vertical (constant tilt rate) may be used to form atransition from a slant hole section or a horizontal section to avertical section of a wellbore. Building sections and dropping sectionsmay also be described as “equilibrium” sections.

The terms “dogleg severity” or “DLS” may be used to describe the rate ofchange in degrees of a wellbore from vertical during drilling of thewellbore. DLS is often measured in degrees per one hundred feet (°/100ft). A straight hole, vertical hole, slant hole or horizontal hole maygenerally have a value of DLS of approximately zero. DLS may bepositive, negative or zero.

Tilt angle (TA) may refer to the angle in degrees from vertical of asegment or portion of a wellbore. A vertical wellbore may have agenerally constant tilt angle (TA) approximately equal to zero. Ahorizontal wellbore may have a generally constant tilt angle (TA)approximately equal to ninety degrees (90°).

Tilt rate (TR) may refer to the rate of change of a wellbore in degreesfrom vertical per hour of drilling. Tilt rate may also be referred to as“steer rate.” Tilt rate may be expressed by the following equation:

${TR} = \frac{d({TA})}{dt}$

where t=drilling time in hours.

Tilt rate (TR) of a drill bit may also be described as DLS multiplied byrate of penetration (ROP), as expressed by the following equation:

TR=DLS×ROP/100=(degrees/hour)

Tilt rate and tilt angle may be used to plan, evaluate, or executedirectional drilling. DLS of respective segments, portions, or sectionsof a wellbore and corresponding tilt rate may be also used to conductsuch planning, evaluation, or execution.

Returning to FIG. 1, as mentioned above, wellbore 60 may generally bedescribed as a directional wellbore or a deviated wellbore havingmultiple segments or sections. In the illustrated embodiment, section 60a of wellbore 60 may include casing 64 extending from well head 24 to aselected downhole location. Remaining portions of wellbore 60 may begenerally described as “open hole” or “uncased.”

Wellbore 60 may be generally described as having multiple sections,segments or portions with respective values of DLS. The tilt rate fordrill bit 100 during formation of wellbore 60 may be a function of DLSfor each segment, section or portion of wellbore 60 multiplied by theROP for drill bit 100 during formation of the respective segment,section or portion thereof. The tilt rate of drill bit 100 duringformation of straight hole sections (e.g., vertical section 60 a) may beapproximately equal to zero. The DLS capability, and consequently thetilt rate capability, of drilling equipment such as a downhole drillingtool for use in a directional drilling system 20—for example, a toolincluding drill bit 100—amy be affected by the amount of hydraulicpressure used to steer drill bit 100. For example, the greater thepressure, the more a drill bit may attempt to move in certain direction,which may affect the tilt rate. Examples of wellbore segments includingdifferent DLS values may be illustrated in sections 60 a-60 f.

Section 60 a extending from well head 24 may be generally described as avertical, straight hole section with a DLS value approximately equal tozero. When the value of DLS is zero, drill bit 100 may have a tilt rateof approximately zero during formation of the corresponding section ofwellbore 60.

A first transition from vertical section 60 a may be described as kickoff section 60 b. For some applications the value of DLS for kick offsection 60 b may be greater than zero and may vary from the end ofvertical section 60 a to the beginning of a second transition segment orbuilding section 60 c. Building section 60 c may be formed withrelatively constant radius 70 c and a substantially constant value ofDLS. Slant hole (or “holding”) section 60 d may extend from buildsection 60 c opposite from second section 60 b. Slant holes section 60 dmay have a DLS of approximately zero.

Drop section 60 e may start at the end of holding section 60 d and mayhave a generally downward looking profile. Drop section 60 e may haverelatively constant radius 70 e. Section 60 f may also be a holdingsection or slant hole section with a DLS of approximately zero. Section60 f as shown in FIG. 1 is being formed by drill bit 100, BHA 90, drillstring 32 and associated components of drilling system 20.

Various directional drilling techniques and associated components of BHA90 may be used to form directional wellbore 60. For example BHA 90 mayinclude a push-the-bit directional drilling system (such as the drillingsystem described with respect to FIG. 4) or a point-the-bit directionaldrilling system (such as the drilling system described with respect toFIG. 5).

BHA 90 may be formed from a wide variety of components configured toform wellbore 60. For example, BHA 90 may include, but is not limitedto, drill bits (e.g., drill bit 100), drill collars, rotary steeringtools, directional drilling tools, downhole drilling motors, reamers,hole enlargers or stabilizers. The number of components such as drillcollars and different types of components included with BHA 90 maydepend upon anticipated drilling conditions and the type of wellborethat may be formed using drill string 32 and drill bit 100.

BHA 90 may also include various components associated with an MWD system(described below with respect to FIG. 7). These components may includetypes of well logging tools (not expressly shown) and other downholedrilling tools associated with directional drilling of a wellbore.Examples of such logging tools and/or directional drilling tools mayinclude, but are not limited to, acoustic, neutron, gamma ray, density,photoelectric, nuclear magnetic resonance, rotary steering tools and/orany other commercially available well tool. Further, the MWD system ofBHA 90 may include pressure sensors (not expressly shown) configured tomeasure the amount of hydraulic pressure being used to steer drill bit100, which may indicate drilling parameters including, but not limitedto, cutting element wear, drilling tool performance, drilling direction,drill bit damage, and/or formation changes. Accordingly, the pressuresensors and their associated hydraulic pressure readings may be used todetermine drilling parameters such as the wear of cutting elements ofdrill bit 100 and/or transitions between formation types as mentionedabove and further detailed below with respect to FIGS. 7 and 8.

Movement or motion of a drill bit and associated drilling equipment inthree dimensions (3D) during formation of a segment, section or portionof a wellbore may be defined by a Cartesian coordinate system (X, Y, andZ axes) and/or a spherical coordinate system (two angles φ and θ and asingle radius ρ) in accordance with teachings of the present disclosure.Examples of Cartesian coordinate systems are shown in FIGS. 2A and 3B.The location of downhole drilling equipment or tools and adjacentportions of a wellbore may be translated between a Cartesian coordinatesystem and a spherical coordinate system.

A Cartesian coordinate system generally includes a Z axis and an X axisand a Y axis that extend normal to each other and normal to the Z axis.See for example FIG. 2A. A Cartesian bit coordinate system may bedefined by a Z axis extending along a rotational axis or bit rotationalaxis of the drill bit. See FIG. 2A. A Cartesian hole coordinate system(sometimes referred to as a “downhole coordinate system” or a “wellborecoordinate system”) may be defined by a Z axis extending along arotational axis of the wellbore. See FIG. 3B. In FIG. 2A the X, Y and Zaxes include subscript _((b)) to indicate a “bit coordinate system.” InFIGS. 3A, 3B and 3C the X, Y and Z axes include subscript _((h)) toindicate a “hole coordinate system.”

FIG. 2A is a schematic drawing showing an example drill bit 100. In someembodiments, drill bit 100 may be configured to be used with BHA 90configured to steer drill bit 100 using hydraulic pressure using adirectional drilling system such as a push-the-bit directional drillingsystem or a point-the-bit directional drilling system, as describedbelow with respect to FIGS. 4 and 5, respectively. Drill bit 100 mayinclude bit body 120 having a plurality of blades 128 formed on bit body120 with respective junk slots or fluid flow paths 140 formedtherebetween. In one embodiment, drill bit 100 may be a rotary drill bitthat may be any suitable type of fixed cutter drill bits, drag bits,matrix drill bits, steel body drill bits, roller cone drill bits, rotarycone drill bits and rock bits operable to form a wellbore extendingthrough one or more downhole formations (e.g. wellbore 60). Rotary drillbits and associated components formed may have many different designs,configurations and/or dimensions. A rotary drill bit or other downholedrilling tool may have multiple components, segments or portions. Forexample, one component of a drill bit may be described as a “cuttingface profile” or “bit face profile” responsible for removal of formationmaterials to form an associated wellbore. For some types of drill bitsthe “cutting face profile” or “bit face profile” may be further dividedinto three segments such as “inner cutters or cone cutters,” “nosecutters” and/or “shoulder cutters.”

Drill bit 100 may include a cutting structure. A cutting structure mayinclude various combinations and arrangements of cutting elements,impact arrestors and/or gage cutters formed on exterior portions of arotary drill bit and/or sleeve. Some rotary drill bits and/or sleevesmay include one or more blades extending from an associated bit bodywith cutters disposed of the blades. Such blades may also be referred toas “cutter blades.” Various configurations of blades and cutters may beused to form cutting structures for a rotary drill bit and/or sleeve.

In the illustrated embodiment, the cutting structure associated withdrill bit 100 may include a plurality of cutting elements 130 disposedon the exterior portions of each blade 128. Cutting elements 130 may beany suitable type of cutters, compacts, buttons, inserts and gagecutters satisfactory for use with a wide variety of drill bits. Impactarrestors 142 may be included as part of the cutting structure on sometypes of rotary drill bits and may sometimes function as cuttingelements to remove formation materials from adjacent portions of awellbore. Polycrystalline diamond compacts (PDC) and tungsten carbideinserts are often used to form cutting elements or cutters. Varioustypes of other hard, abrasive materials may also be satisfactorily usedto form cutting elements or cutters.

Drill bit 100 may translate linearly relative to the X, Y and Z axes asshown in FIG. 2A (three (3) degrees of freedom). Drill bit 100 may alsorotate relative to the X, Y and Z axes (three (3) additional degrees offreedom). As a result, movement of drill bit 100 relative to the X, Yand Z axes as shown in FIGS. 2A and 2 B, drill bit 100 may be describedas having six (6) degrees of freedom. During drilling, these parametersmay be expressed by WOB, bit side forces, RPM, ROP, DLS, bend length(B_(L)) and azimuth angle of an associated tilt plane. Thus, factorsthat affect WOB and/or DLS in turn affect the movement of drill bit 100.

Referring back to FIG. 1, when sufficient force from drill string 32 hasbeen applied to drill bit 100, cutting elements 130 may engage andremove adjacent portions of a downhole formation at bottom hole or end62 of wellbore 60. Removing such formation materials may allow downholedrilling equipment including drill bit 100 and associated drill string32 to move linearly relative to adjacent portions of wellbore 60.

Various kinematic parameters associated with forming a wellbore using adrill bit may be based upon RPM and ROP of the drill bit into adjacentportions of a downhole formation. Arrow 110 in FIG. 2A may be used torepresent forces which move drill bit 100 linearly relative torotational axis 104 a. Such linear forces typically result from weightapplied to drill bit 100 by drill string 32, resulting in WOB. If thereis no weight on drill bit 100, no axial penetration may occur at end orbottom hole 62 of wellbore 60.

Rotational force 112 may be applied to drill bit 100 by rotation ofdrill string 32. RPM of drill bit 100 may be a function of rotationalforce 112. Rotation speed of drill bit 100 is generally defined relativeto the rotational axis of drill bit 100 which corresponds with Z axis104.

Arrow 116 indicates rotational forces which may be applied to drill bit100 relative to X axis 106. Arrow 118 indicates rotational forces whichmay be applied to drill bit 100 relative to Y axis 108. Rotationalforces 116 and 118 may result from interaction between cutting elements130 disposed on exterior portions of drill bit 100 and adjacent portionsof bottom hole 62 during the forming of wellbore 60. Rotational forcesapplied to drill bit 100 along X axis 106 and Y axis 108 may result intilting of drill bit 100 relative to adjacent portions of drill string32 and wellbore 60.

FIG. 2B is a schematic drawing of drill bit 100 disposed within verticalsection or straight hole section 60 a of wellbore 60. During thedrilling of a vertical section or any other straight hole section of awellbore, the bit rotational axis of drill bit 100 may generally bealigned with a corresponding rotational axis of the straight holesection. The incremental change or the incremental movement of drill bit100 in a linear direction during a single revolution may be representedby ΔZ in FIG. 2B.

Rate of penetration of a drill bit is typically a function of both WOBand RPM. For some applications a downhole motor (not expressly shown)may be provided as part of BHA 90 to also rotate drill bit 100. The ROPof a drill bit is generally stated in feet per hour.

The axial penetration of drill bit 100 may be defined relative to bitrotational axis 104 a in an associated bit coordinate system. Anequivalent side penetration rate or lateral penetration rate due to tiltmotion of drill bit 100 may be defined relative to an associated holecoordinate system. Examples of a hole coordinate system are shown inFIGS. 3A, 3B and 3C.

FIGS. 3A, 3B and 3C are graphical representations of various kinematicparameters which may be satisfactorily used to model or simulatedrilling segments or portions of a wellbore having a value of DLSgreater than zero. FIG. 3A is a schematic illustration showing a sideforce 114 applied to rotary drill bit 100 at an instant in time, inaccordance with some embodiments of the present disclosure. FIG. 3Ashows a schematic cross-section of drill bit 100 in two dimensionsrelative to a Cartesian bit coordinate system. The bit coordinate systemis defined in part by X axis 106 and Y axis 108 extending from bitrotational axis 104 a. FIG. 3B is a schematic illustration showing atrajectory of a directional wellbore and rotary drill bit 100 disposedin a tilt plane at an instant of time in a three dimensional Cartesianhole coordinate system, in accordance with some embodiments of thepresent disclosure. FIG. 3C is a schematic illustration showing rotarydrill bit 100 of FIG. 3B at the same instant of time in a twodimensional Cartesian hole coordinate system. FIGS. 3B and 3C showgraphical representations of drill bit 100 during drilling of atransition segment such as kick off segment 60 b of wellbore 60 in aCartesian hole coordinate system defined in part by Z axis 74, X axis 76and Y axis 78.

A side force is generally applied to a drill bit by an associateddirectional drilling system to form a wellbore having a desired profileor trajectory using the drill bit. For a given set of drilling equipmentdesign parameters and a given set of downhole drilling conditions, arespective side force must be applied to an associated drill bit toachieve a desired DLS or tilt rate.

FIG. 3A shows side force 114 extending at angle 72 relative to X axis106. Side force 114 may be applied to drill bit 100 by directionaldrilling system 20. Angle 72 (sometimes referred to as an “azimuth”angle) extends from rotational axis 104 a of drill bit 100 andrepresents the angle at which side force 114 may be applied to drill bit100. For some applications side force 114 may be applied to drill bit100 at a relatively constant azimuth angle.

Directional drilling systems such as drill bit steering unit 92 a shownin FIG. 4 and drill bit steering unit 92 b shown in FIG. 5, may be usedto either vary the amount of side force 114 or to maintain a relativelyconstant amount of side force 114 applied to drill bit 100. Directionaldrilling systems may also vary the azimuth angle at which a side forceis applied to a drill bit to correspond with a desired wellboretrajectory or drill path. In one embodiment, the amount of side force114 required to achieve a desired DLS or the ability to select aparticular an azimuth angle may depend upon a variety of factors,including, but not limited to, bit wear and formation hardness.

During drilling of straight hole segments of wellbore 60, side forcesapplied to drill bit 100 may be substantially minimized (approximatelyzero side forces) or may be balanced such that the resultant value ofany side forces may be approximately zero. Straight hole segments ofwellbore 60 as shown in FIG. 1 include, but are not limited to, verticalsection 60 a, holding section or slant hole section 60 d, and holdingsection or slant hole section 60 f During formation of straight holesegments of wellbore 60, the primary direction of movement ortranslation of drill bit 100 may be generally linear relative to anassociated longitudinal axis of the respective wellbore segment andrelative to associated bit rotational axis 104 a.

During the drilling of portions of wellbore 60 having a DLS with a valuegreater than zero or less than zero, a side force (F_(s)) or equivalentside force may be applied to an associated drill bit to cause formationof corresponding wellbore segments 60 b, 60 c and 60 e. For someapplications such as when a push-the-bit directional drilling system isused with a drill bit, an applied side force may result in a combinationof bit tilting and side cutting or lateral penetration of adjacentportions of a wellbore. For other applications such as when apoint-the-bit directional drilling system is used with an associateddrill bit, side cutting or lateral penetration may generally be small ormay not even occur. When a point-the-bit directional drilling system isused with a drill bit, directional portions of a wellbore may be formedprimarily as a result of bit penetration along an associated bitrotational axis and tilting of the drill bit relative to a wellboreaxis. An example of operation of a push-the-bit directional drillingsystem is shown in FIG. 4 below and an example of a point-the-bitdirectional drilling system is shown in FIG. 5 below.

Side force 114 may be adjusted or varied to cause associated cuttingelements 130 to engage adjacent portions of a downhole formation so thatdrill bit 100 may follow profile or trajectory 68 a, as shown in FIG.3B, or any other desired profile. Respective tilting angles of drill bit100 may vary along the length of trajectory 68 a. Arrow 174 correspondswith the variable tilt rate of drill bit 100 relative to vertical at anyone location along trajectory 68 a. During movement of drill bit 100along profile or trajectory 68 a, the respective tilt angle at eachlocation on trajectory 68 a may generally increase relative to Z axis 74of the hole coordinate system shown in FIG. 3B. For embodiments such asshown in FIG. 3B, the tilt angle at each point on trajectory 68 a may beapproximately equal to an angle formed by a respective tangent extendingfrom the point in question and intersecting Z axis 74. Therefore, thetilt rate may also vary along the length of trajectory 168.

During the formation of kick off segment 60 b and any other portions ofa wellbore in which the value of DLS is either greater than zero or lessthan zero and is not constant, drill bit 100 may experience side cuttingmotion, bit tilting motion and axial penetration in a directionassociated with cutting or removing of formation materials from the endor bottom of a wellbore.

For embodiments as shown in FIGS. 3A, 3B and 3C directional drillingsystem 20 may cause drill bit 100 to move in the same azimuth plane 170during formation of kick off segment 60 b. FIGS. 3B and 3C showrelatively constant azimuth plane angle 172 relative to the X axis 76and Y axis 78. Arrow 114 as shown in FIG. 3A represents a side forceapplied to drill bit 100 by directional drilling system 20. Arrow 114may generally extend normal to rotational axis 104 a of drill bit 100.Arrow 114 may also be disposed in tilt plane 170. A side force appliedto a drill bit in a tilt plane by an associate drill bit steering unitor directional drilling system may also be referred to as a “steerforce.”

During the formation of a directional wellbore such as shown in FIG. 3B,without consideration of bit walk, rotational axis 104 a of drill bit100 and a longitudinal axis of BHA 90 may generally lie in tilt plane170. Drill bit 100 may experience tilting motion in tilt plane 170 whilerotating relative to rotational axis 104 a. Tilting motion may resultfrom a side force or steer force applied to drill bit 100 by adirectional steering unit. Tilting motion often results from acombination of side forces and/or axial forces applied to drill bit 100by directional drilling system 20.

In both point-the-bit and push-the-bit directional drilling systems,side force 114 may be a result of hydraulics used to steer drill bit 100in the desired direction. Accordingly, the amount of hydraulic pressureapplied may relate to the tilt rate of drill bit 100. Additionally, ascutting elements 130 of drill bit 100 wear from cutting into theformation, a greater amount of hydraulic pressure may be required toachieve the same amount of tilt and tilt rate. Further, the hydraulicpressure may be adjusted while transitioning between formations havingdifferent degrees of hardness to maintain substantially the same tiltrate. Additionally, cyclic changes in the hydraulic pressure mayindicate inconsistent cutting by drill bit 100. Therefore, the hydraulicpressure may indicate drilling parameters such as, but not limited tocutting element wear, drilling tool performance, transitions from oneformation type to another, and/or formation tendencies (e.g., thedirection the drilling tool may be steered to overcome the dip angle ofthe formation).

FIG. 4 illustrates aspects of push-the-bit directional drilling systemsthat may be used in accordance with embodiments of the presentdisclosure. FIG. 4 shows portions of BHA 90 a disposed in generallyvertical portion 60 a of wellbore 60 as rotary drill bit 100 a begins toform kick off segment 60 b. BHA 90 a may include rotary drill bitsteering unit 92 a operable to apply side force 114 to rotary drill bit100 a. Steering unit 92 a may be one portion of a push-the-bitdirectional drilling system or rotary steerable system (RSS).

In many push-the-bit RSS, a number of expandable thrust pads may belocated a selected distance above an associated rotary drill bit.Expandable thrust pads may be used to bias the rotary drill bit along adesired trajectory. Several steering mechanisms may be used, butpush-the-bit principles are generally the same. A side force is appliedto the bit by the RSS from a fulcrum point disposed uphole from the RSS.As mentioned above, the side force may be applied using hydraulicpressure. Rotary drill bits used with push-the-bit RSS typically have ashort gage pad length in order to satisfactorily steer the bit. Near bitstabilizers or sleeves are generally not used with push-the-bit RSS.

Push-the-bit systems may generally include simultaneous axialpenetration and side penetration in order to drill directionally. Bitmotion associated with push-the-bit directional drilling systems isoften a combination of axial bit penetration, bit rotation, bit sidecutting and bit tilting.

In the illustrated embodiment, steering unit 92 a may extend one or morearms or thrust pads 94 a to apply force 114 a to adjacent portions ofwellbore 60 and maintain desired contact between steering unit 92 a andadjacent portions of wellbore 60. Side forces 114 and 114 a may beapproximately equal to each other. If there is no weight on rotary drillbit 100 a, no axial penetration may occur at end or bottom hole 62 ofwellbore 60. Side cutting may generally occur as portions of rotarydrill bit 100 a engage and remove adjacent portions of wellbore 60 a.

Steering unit 92 a may extend thrust pads 94 a to apply side force 114 ausing a hydraulic system that applies hydraulic pressure to thrust pads94 a. Therefore, as the hydraulic pressure increases, side force 114 amay increase. As mentioned above, the amount of side force 114 arequired to steer drill bit 100 a at a certain tilt rate may be based atleast partially on the wear of cutting elements 130 of drill bit 100 aand the hardness of the formation being drilled. Therefore, thehydraulic pressure may be used to determine cutting element wear and/orformation changes, among other drilling parameters. Therefore, apush-the-bit system, such as described above with respect to FIG. 4 maybe used to create a directional wellbore such as directional wellbore60. Additionally, as described above, hydraulic pressure used to createside forces may be measured to determine drilling parameters including,but not limited to, cutting element wear, drilling tool performance,and/or formation changes.

FIG. 5 illustrates aspects of point-the-bit directional drilling systemsthat may be used in accordance with some embodiments of the presentdisclosure. Point-the-bit directional drilling systems such as shown inFIG. 5 may generally create of a fulcrum point between an associated bitcutting structure or bit face profile and associated point-the-bitrotary steering system. The fulcrum point may be formed by a stabilizeror a sleeve disposed uphole from the associated rotary drill bit.

FIG. 5 shows portions of BHA 90 b disposed in a generally verticalsection of wellbore 60 a as rotary drill bit 100 b begins to form kickoff segment 60 b. BHA 90 b includes rotary drill bit steering unit 92 bwhich may provide one portion of a point-the-bit directional drillingsystem. A point-the-bit directional drilling system may generate adeflection which deforms portions of an associated drill string todirect an associated drill bit in a desired trajectory. There areseveral steering or deflection mechanisms associated with point-the-bitrotary steering systems. A common feature of point-the-bit RSS is oftena deflection angle generated between the rotational axis of anassociated rotary drill bit and longitudinal axis of an associatedwellbore.

In some point-the-bit directional drilling systems the deflectionmechanisms may create the deflection angle using hydraulic pressure.Therefore, as the hydraulic pressure increases, side force 114 b causedby drill bit 100 b may increase. As mentioned above, the amount of sideforce 114 b required to steer drill bit 100 b at a certain tilt rate maybe based at least partially on the wear of cutting elements 130 of drillbit 100 b and the hardness of the formation being drilled. Therefore,the hydraulic pressure may be used to determine cutting element wearand/or formation changes among other drilling parameters.

Point-the-bit directional drilling systems may form a directionalwellbore using a combination of axial bit penetration, bit rotation andbit tilting. Point-the-bit directional drilling systems may not produceside penetration in as high a magnitude as, for example, push-the-bitdirection steering systems such as steering unit 92 a in FIG. 4. Oneexample of a point-the-bit directional drilling system is the Geo-Pilot®Rotary Steerable System available from Sperry Drilling Services atHalliburton Company.

Therefore, a point-the-bit system, such as described above with respectto FIG. 5 may be used to create a directional wellbore such asdirectional wellbore 60. Additionally, as described above, hydraulicpressure used to deflect the drill bit and create side forces may bemeasured to determine drilling parameters including, but not limited to,cutting element wear, drilling tool performance and/or formationchanges.

FIG. 6 is a schematic illustration of rotary drill bit 100 showingchanges in bit side forces with respect to changes in dog leg severity(DLS) during drilling of a directional wellbore, in accordance with someembodiments of the present disclosure. FIG. 6 is a schematic drawingshowing drill bit 100 in solid lines in a first position associated withforming a generally vertical section of a wellbore. Drill bit 100 isalso shown in dotted lines in FIG. 6 showing a directional portion of awellbore such as kick off segment 60 a. The graph shown in FIG. 6indicates that the amount of bit side force required to produce a tiltrate corresponding with the associated DLS may generally increase as thedogleg severity of the deviated wellbore increases. The shape of curve194 as shown in FIG. 6 may be a function of downhole drilling tooldesign parameters and/or associated downhole drilling conditions. Forexample, the hydraulic force used to steer a drill bit may impact theand consequently impact the ability to drill a wellb ore.

FIG. 7 illustrates a block diagram of an example of directional drillingequipment 700 and an associated MWD system 702. MWD system 702 mayinclude one or more sensors 705 a-705 i located along a drill string(e.g., drill string 32 of FIG. 1) that may be configured to measure avariety of parameters associated with drilling that may be used for welllogging. In some embodiments, one or more of sensors 705 a-705 i may bedisposed at various locations along a bottom hole assembly such as BHA90 described above with respect to FIG. 1.

Sensors 705 a-705 i may be configured to measure any number ofparameters associated with drilling into a formation, including, but notlimited to, porosity, rock strength, resistivity, density and directionchanges. Sensors 705 a-705 i may measure these parameters using anysuitable methods and may be any one of acoustic, neutron, gamma ray,density, photoelectric, and nuclear magnetic resonance tools.

Further, according to embodiments of the present disclosure, sensors 705a-705 i may include one or more hydraulic pressure sensors configured tomeasure hydraulic pressure used to steer a drill bit (e.g., drill bit100 of FIGS. 1-5C). The hydraulic pressure sensors may be, for example,a strain gage, a quartz transducer pressure sensor, or any othersuitable hydraulic pressure sensor. The placement of the hydraulicpressure sensors may vary according to the particular sensor type, butin some embodiments, the hydraulic pressure sensors may be placedin-line with a hydraulic control circuit or fluidly coupled with thehydraulic control circuit.

As mentioned above, the hydraulic pressure used to steer a drill bit mayindicate drilling parameters including, but not limited to, wearassociated with cutting elements, drilling tool performance and/orformation changes. Accordingly, one or more hydraulic pressure sensorsthat may be included with sensors 705 a-705 i may provide informationindicative of one or more drilling parameters.

Sensors 705 a-705 i of MWD system 702 may be communicatively coupled toone or more input devices 704 of directional drilling equipment 700 suchthat directional drilling equipment 700 may receive logging data andother information (including hydraulic pressure) gathered by MWD system702.

Input device 704 may direct the data received from MWD system 702 to adata processing system 706. Data processing system 706 may include aprocessor coupled to a memory. The processor may comprise, for example amicroprocessor, microcontroller, digital signal processor (DSP),application specific integrated circuit (ASIC), or any other digital oranalog circuitry configured to interpret and/or execute programinstructions and/or process data. In some embodiments, the processor mayinterpret and/or execute program instructions and/or process data storedin the memory. Such program instructions or process data may constituteportions of software for carrying out simulation, monitoring, or controlof the directional drilling described herein. The memory may include anysystem, device, or apparatus configured to hold and/or house one or morememory modules; for example, the memory may include read-only memory,random access memory, solid state memory, or disk-based memory. Eachmemory module may include any system, device or apparatus configured toretain program instructions and/or data for a period of time (e.g.,computer-readable non-transitory media).

In some embodiments, data processing system 706 may be configured todetermine changes in hydraulic pressure as measured by one or moresensors 705 a-705 i. Based on the changes in hydraulic pressure andother data being measured by MWD system 702, data processing system 706may determine drilling parameters including, but not limited to,information related to cutting element wear, drilling tool performanceand/or a change in the formation being drilled.

For example, as indicated above, some directional drilling systems mayhave a fixed oil volume pressure that may be related to the side forcebeing exerted by the bit. In other directional drilling systems, thehydraulic pressure may be dynamically changed during drilling based onfeedback systems indicating trajectory and such. As the cutting elementsof a drilling tool (e.g., drill bit) wear during drilling, the sideforce may increase, which may result in an increase in the hydraulicpressure. Typically, a the cutting elements of a drilling tool maygradually wear as drilling occurs, therefore, by monitoring a relativelygradual increase in hydraulic pressure, it may be determined that thecutting elements of a drilling tool (e.g., drill bit) may beexperiencing increased wear. Additionally, in some instances where backup cutting elements are included on a drilling tool, a decrease inhydraulic pressure (after an increase in the pressure due to wear on theprimary cutting elements) may indicate that relatively unworn backupcutting elements may have begun engaging the formation.

Further, a change from one formation to another formation may alsoresult in a change in side force based on differences in the hardnessbetween the formations. In some instances, the change from one formationto another may be abrupt, such that a relatively fast change inhydraulic pressure may indicate that a formation change has occurredinstead of indicating wear on the cutting elements of the drill bit. Inother words, a high rate of pressure change may indicate an abruptchange in formation, while a low rate of pressure change may indicatewear on the cutting elements of the drill bit. In the same oralternative embodiments, a determination that a change in the hydraulicpressure is due to a formation change may be verified with othermeasurements taken by MWD system 702, such as porosity, rock strength,resistivity, density etc. Additionally, measurements may be made bywire-line system of an offset well that is close in proximity to thesubject well.

Additionally, the hydraulic pressure measurements may indicate drill bitperformance. For example, a cyclic change in hydraulic pressure mayindicate that some sections of the drill bit are engaging and cuttinginto the formation more effectively than other areas. Accordingly, byusing these cyclic changes, one or more design changes may be made tothe drill bit to improve the overall engagement of the bit with aformation. Furthermore, the hydraulic pressure measurements may indicateperformance of the drilling system in the wellbore. For example, themeasurements may be used to adjust the fluid flow rate in the wellbore,drill string speed, steering direction of the drilling system, and theWOB in order to improve drilling performance.

Processing system 706 may be communicatively coupled to various displays708 that are part of directional drilling equipment 700 such thatinformation processed by processing system 706 (e.g., cutting elementwear, formation changes, drilling tool performance, etc.) may beconveyed to operators of directional drilling equipment 700. Printer 709and associated printouts 709 a may also be used to report theperformance of the associated drill string, BHA and drill bit (e.g.,drilling string 32, BHA 90 and associated drill bit 100, as shown inFIG. 1.) Outputs 707 may be communicated to various componentsassociated with operating the associated drilling rig (e.g., drillingrig 22), to various remote locations to monitor and/or control theperformance of the directional drilling system (e.g., directionaldrilling system 20), or to users simulating the drilling of thewellbore, (e.g., wellbore 60).

Accordingly, by measuring and analyzing hydraulic pressure measurementsprovided by one or more sensors 705 of MWD system 702, directionaldrilling equipment 700 and MWD system 702 may be used to determinedrilling parameters that may be dependent on the hydraulic pressure usedin directional drilling systems. Some of the various parametersindicated by hydraulic pressure may be cutting element wear, formationchanges, drilling tool performance etc. Therefore, MWD system 702 anddirectional drilling equipment 700 may provide and process hydraulicpressure information that may help improve drilling efficiency.

Modifications, additions, or omissions may be made to FIG. 7 withoutdeparting from the scope of the present disclosure. For example, thenumber of sensors 705 and the parameters measured by sensors 705 mayvary depending on the drilling application. Further, other drillingparameters may be determined based on the hydraulic pressure of adirectional drilling system.

FIG. 8 is an illustration of an example method 800 for determiningdrilling parameters based on hydraulic pressure. Method 800 may beperformed by any suitable system, apparatus, or device. As an examplemethod 800 is described as being performed by processing system 706described with respect to FIG. 7, however, any other suitable system,apparatus or device may be used.

Method 800 may start, and at step 802 processing system 706 may receivehydraulic pressure measurements from one or more hydraulic pressuresensors of sensors 705 a-705 i included in MWD system 702. As mentionedabove, one or more of sensors 705 a-705 i may be configured to measurehydraulic pressure used to steer a drill bit in a directional drillingsystem such as a point-the-bit drilling system or a push-the-bitdrilling system. At step 804, processing system 706 may monitor thereceived hydraulic pressure measurements. At step 806, processing system706 may determine whether or not a change in the hydraulic pressure hasoccurred based on the monitored hydraulic pressure measurements. If achange in hydraulic pressure has not occurred, method 800 may return tostep 804, otherwise, method 800 may proceed to step 808.

At step 808, processing system 706 may determine a cause in the changeof the hydraulic pressure. For example, as explained above with respectto FIG. 7, if an upward change in hydraulic pressure is relativelygradual, the change may indicate cutting element wear of a drilling tool(e.g. a drill bit). A gradual increase in pressure and then a decreasein pressure may indicate that secondary cutting elements have nowengaged the formation. If a change in hydraulic pressure is cyclic, thechange may indicate that one area of a drilling tool (e.g., drill) bitis more effective at cutting into a formation than another. If thechange is relatively abrupt, processing system 706 may determine thatthe change is due to a formation change, as mentioned earlier, in suchinstances processing system 706 may use other measurements made by MWDsystem 702 (e.g., density, porosity, resistivity, rock strength, etc.)to verify such a conclusion.

At step 810, based on the determined cause of the change in hydraulicpressure, one or more changes may be made to the drilling process and/orthe drill bit. For example, if it is determined that the cuttingelements of the drill bit are sufficiently worn, the cutting elements ordrill bit may be replaced. Further, changes in the formation may resultin changes in drilling such as, but not limited to, drilling RPM, WOB,etc. Additionally, a determination of an amount of cutting element wearand engagement of secondary cutting elements may be used in conjunctionwith depth and formation information to better design drill bits.

Modifications, additions, or omissions may be made to method 800 withoutdeparting from the scope of the present disclosure. For example, one ormore steps may be broken into more specific components, further one ormore steps may be performed at the same time.

Although the present disclosure and its advantages have been describedin detail, it should be understood that various changes, substitutionsand alterations can be made herein without departing from the spirit andscope of the disclosure as defined by the following claims.

What is claimed is: application: 1.-25. (canceled)
 26. A method ofdetermining a drilling parameter associated with a directional drillingsystem, comprising: measuring a hydraulic pressure used by a deflectionmechanism of a directional drilling system to generate a deflectionangle between a rotational axis of a drill bit and a longitudinal axisof a wellbore during drilling of the wellbore; detecting a change in thehydraulic pressure; and determining a drilling parameter based on thedetected change in the hydraulic pressure.
 27. The method of claim 26,wherein determining the drilling parameter further comprises determiningcutting element wear based on a gradual change in the hydraulicpressure.
 28. The method of claim 26, wherein determining the drillingparameter further comprises determining a formation change based on anabrupt change in the hydraulic pressure.
 29. The method of claim 26,wherein determining the drilling parameter further comprises determininguneven cutting by a drilling tool based on a cyclic change in thehydraulic pressure.
 30. The method of claim 26, wherein the directionaldrilling system comprises a point-the-bit directional drilling system.31. The method of claim 26, further comprising measuring a formationcharacteristic and determining the drilling parameter based on theformation characteristic and the detected change in the hydraulicpressure.
 32. The method of claim 26, further comprising adjustingdrilling based on the determined drilling parameter.
 33. The method ofclaim 26, further comprising designing a drilling tool based on thedetermined drilling parameter.
 34. A directional drilling systemcomprising: a drilling tool including a drill bit; a steering mechanismincluding a deflection mechanism capable of generating a deflectionangle between a rotational axis of the drill bit and a longitudinal axisof a wellbore using a hydraulic pressure, the steering mechanismconfigured to direct the drill bit in a desired trajectory using thehydraulic pressure; a hydraulic pressure sensor coupled to the steeringmechanism and configured to measure the hydraulic pressure; anddirectional drilling equipment configured to: receive the measuredhydraulic pressure from the hydraulic pressure sensor; detect a changein the measured hydraulic pressure; and determine a drilling parameterbased on the detected change in the measured hydraulic pressure.
 35. Thedirectional drilling system of claim 34, wherein the drilling parametercomprises wear associated with a cutting element of the drilling tool.36. The directional drilling system of claim 34, wherein the drillingparameter comprises a formation change.
 37. The directional drillingsystem of claim 34, wherein the drilling parameter comprises unevencutting by the drilling tool.
 38. The directional drilling system ofclaim 34, further comprising a formation sensor configured to measure aformation characteristic, wherein the directional drilling equipment isfurther configured to: receive the measured formation characteristic;and determine the drilling parameter based on the formationcharacteristic and the detected change in the measured hydraulicpressure.
 39. The directional drilling system of claim 34, wherein thedirectional drilling equipment is further configured to adjust drillingbased on the determined drilling parameter.
 40. Directional drillingequipment comprising: a processor; a computer readable memorycommunicatively coupled to the processor; and processing instructionsencoded in the computer readable memory, the processing instructions,when executed by the processor, operable to perform operationscomprising: receiving a hydraulic pressure measurement associated with ahydraulic pressure used by a deflection mechanism to generate adeflection angle between a rotational axis of a drill bit and alongitudinal axis of a wellbore; detecting a change in the hydraulicpressure measurement; and determining a drilling parameter based on thedetected change in the hydraulic pressure measurement.
 41. Thedirectional drilling equipment of claim 40, wherein determining thedrilling parameter further comprises determining cutting element wearbased on a gradual change in the hydraulic pressure measurement.
 42. Thedirectional drilling equipment of claim 40, wherein determining thedrilling parameter further comprises determining a formation changebased on an abrupt change in the hydraulic pressure measurement.
 43. Thedirectional drilling equipment of claim 40, wherein determining thedrilling parameter further comprises determining uneven cutting by adrilling tool based on a cyclic change in the hydraulic pressuremeasurement.
 44. The directional drilling equipment of claim 40, whereinthe processing instructions, when executed by the processor, are furtheroperable to perform operations comprising: receiving a formationcharacteristic measurement; and determining the drilling parameter basedon the formation characteristic measurement and the detected change inthe hydraulic pressure measurement.
 45. The directional drillingequipment of claim 40, wherein the processing instructions, whenexecuted by the processor, are further operable to perform operationscomprising adjusting drilling based on the determined drillingparameter.